Some gas-lift wells will not sit still. Instead of a smooth, steady flow, they surge: production comes in slugs, casing pressure swings up and down, and gas seems to go in fits and starts. This behavior is called heading, or heading instability, and it is one of the most common and most frustrating problems in gas-lift operation. This guide explains what heading is, why an oversized orifice or too much gas can trigger it, what it looks like in surface pressure and flow, and how tuning and automation calm a heading well.
Gas Lift Heading Instability in one line: Gas lift heading instability is a self-sustaining cycle in which a gas-lift well oscillates between loading with liquid and unloading in a gas-driven slug, instead of flowing steadily. The casing pressure builds, dumps a slug of gas into the tubing, blows the well out, and then reloads, repeating on a period of minutes to hours.
Heading is a feedback loop between the annulus and the tubing. During the loading phase, liquid accumulates in the tubing above the injection point while the annulus slowly builds casing pressure. The heavy liquid column raises the tubing pressure at the valve, which chokes back the gas passing in, so even less gas enters and the column keeps growing. Pressure energy is being stored in the annulus rather than lifting fluid.
Eventually the annulus pressure wins. A large volume of gas dumps through the valve, aerates and lightens the liquid column, and the well unloads in a violent slug of gas and liquid. That surge sharply drops the tubing pressure and often the casing pressure with it. With the column blown out, liquid begins to accumulate again and the whole cycle restarts. Because the mechanism sustains itself, a heading well can cycle indefinitely with no outside trigger.
The physics is often described as a density-wave or casing-heading instability, depending on whether the dominant storage is in the tubing fluid density or the annulus gas volume. In both cases the well is trading between two states rather than settling in the middle. The practical result is the same: slugging flow, swinging pressures, and average production that is lower than a stable well would deliver.
Heading is most likely when injection is under-gassed for the conditions, when the operating valve is a large orifice referenced to casing pressure rather than a pressure-limiting valve, or when the well produces at a low, unstable rate near the edge of its lift envelope. An oversized orifice lets the annulus store and release too much gas at once, exaggerating the cycle. Wells that are lifting from a shallow injection point or that have a low reservoir drawdown are especially prone to it.
At the surface the fingerprints are unmistakable once you know them. Casing head pressure rises and falls on a repeating period; tubing pressure spikes during each slug; and the produced liquid and gas rates pulse rather than hold steady. On a trend chart the casing and tubing pressures often trace mirror-image sawtooth patterns. Downstream, the slugs can upset separators and flowlines, tripping high-level or high-pressure alarms as each surge arrives.
The cost of heading is not just nuisance alarms. Slug flow means the well spends part of every cycle loaded and barely producing, so the time-averaged oil rate is below what stable lift would give. Repeated pressure swings also fatigue equipment and make well tests unreliable, because a single measurement lands somewhere on the cycle rather than at a representative steady rate.
The classic fixes attack the storage-and-release mechanism. Reducing the effective injection-port size, or replacing a wide-open orifice with a valve that limits how much gas can pass, cuts the slug volume the annulus can dump. Increasing injection gas rate can push the well past the unstable region into steady flow, and adding a small amount of surface backpressure through the production choke can damp the tubing oscillation. Deeper injection, where achievable, often stabilizes a well that heads from a shallow point.
Because heading is a dynamic loop, the tuning is easier when you can watch the well respond. Adjusting choke or injection while trending casing and tubing pressure lets an operator confirm the cycle amplitude shrinking rather than guessing. Some sites run active stabilization, using a control valve on the injection line or production choke driven by a controller that counteracts the pressure swing, but even manual tuning benefits enormously from seeing the response in near real time.
A cloud SCADA such as Merobix trends casing head pressure, tubing pressure, and flow for each gas-lift well continuously, so a heading well is obvious the moment its traces start to oscillate rather than only during a chance site visit. Engineers can make an injection or choke change from the office and watch on the same dashboard whether the well settles out, turning heading diagnosis and correction into a same-day task instead of a recurring field mystery.
Heading is caused by a feedback loop between the annulus and tubing: liquid loads the tubing while the annulus stores gas pressure, then the stored gas dumps and blows the well out, and the cycle repeats. It is most likely when the well is under-gassed, uses a large orifice referenced to casing pressure, injects from a shallow point, or produces at a low, unstable rate. Any of these lets the annulus store and release too much gas at once.
Common remedies are reducing the effective injection-port size or switching to a valve that limits gas passage, increasing injection gas rate to push the well into stable flow, and adding a little surface backpressure through the choke to damp the oscillation. Deeper injection also helps where achievable. Because heading is dynamic, the fixes are much easier to dial in while watching casing and tubing pressure trends respond.
Yes. During each cycle the well spends part of the time loaded and barely producing, so its time-averaged oil rate is lower than a stable well would deliver. The pressure swings also disturb separators and flowlines and make well tests unrepresentative because a measurement lands somewhere on the cycle rather than at a steady rate. Stabilizing the well usually recovers both the lost average rate and measurement reliability.
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